A plunger lift is an apparatus that is used to increase the productivity of oil and gas wells. In the early stages of a well's life, liquid loading is usually not a problem. When rates are high, the well liquids are carried out of the tubing by the high velocity gas. As a well declines, a critical velocity is reached below which the heavier liquids do not make it to the surface and start to fall back to the bottom exerting back pressure on the formation, thus loading up the well. A plunger system is a method of unloading gas in high ratio oil wells without interrupting production. In operation, the plunger travels to the bottom of the well where the loading fluid is picked up by the plunger and is brought to the surface removing all liquids in the tubing. The plunger also keeps the tubing free of paraffin, salt or scale build-up. A plunger lift system works by cycling a well open and closed. During the open time a plunger interfaces between a liquid slug and gas. The gas below the plunger will push the plunger and liquid to the surface. This removal of the liquid from the tubing bore allows an additional volume of gas to flow from a producing well. A plunger lift requires sufficient gas presence within the well to be functional in driving the system. Oil wells making no gas are thus not plunger lift candidates.
As the flow rate and pressures decline in a well, lifting efficiency declines geometrically. Before long the well begins to “load up”. This is a condition whereby the gas being produced by the formation can no longer carry the liquid being produced to the surface. There are two reasons this occurs. First, as liquid comes in contact with the wall of the production string of tubing, friction occurs. The velocity of the liquid is slowed and some of the liquid adheres to the tubing wall, creating a film of liquid on the tubing wall. This liquid does not reach the surface. Secondly, as the flow velocity continues to slow the gas phase can no longer support liquid in either slug form or droplet form. This liquid, along with the liquid film on the sides of the tubing, begins to fall back to the bottom of the well. In a very aggravated situation there will be liquid in the bottom of the well with only a small amount of gas being produced at the surface. The produced gas must bubble through the liquid at the bottom of the well and then flow to the surface. Because of the low velocity very little liquid, if any, is carried to the surface by the gas. Thus, as explained previously, a plunger lift will act to remove the accumulated liquid.
A typical installation plunger lift system 100 can be seen in FIG. 1. Lubricator assembly 10 is one of the most important components of plunger system 100. Lubricator assembly 10 includes cap 1, integral top bumper spring 2, striking pad 3, and extracting rod 4. Extracting rod 4 may or may not be employed depending on the plunger type. Below lubricator 10 is plunger auto catching device 5 and plunger sensing device 6. Sensing device 6 sends a signal to surface controller 15 upon united plunger mechanism (UPM) 200 at the well top. UPM 200 is shown to represent the plunger of the present invention and will be described below in more detail. Sensing the plunger is used as a programming input to achieve the desired well production, flow times and wellhead operating pressures. Master valve 7 should be sized correctly for the tubing 9 and UPM 200. An incorrectly sized master valve will not allow UPM 200 to pass. Master valve 7 should incorporate a full bore opening equal to the tubing 9 size. An oversized valve will allow gas to bypass the plunger causing it to stall in the valve. If the plunger is to be used in a well with relatively high formation pressures, care must be taken to balance tubing 9 size with the casing 8 size. The bottom of a well is typically equipped with a seating nipple/tubing stop 12. Spring standing valve/bottom hole bumper assembly 11 is located near the tubing bottom. The bumper spring is located above the standing valve and can be manufactured as an integral part of the standing valve or as a separate component of the plunger system.
Surface control equipment usually consists of motor valve(s) 14, sensors 6, pressure recorders 16, etc., and an electronic controller 15 which opens and closes the well at the surface. Well flow ‘F’ proceeds downstream when surface controller 15 opens well head flow valves. Controllers operate on time, or pressure, to open or close the surface valves based on operator-determined requirements for production. Modern electronic controllers incorporate features that are user friendly, easy to program, addressing the shortcomings of mechanical controllers and early electronic controllers. Additional features include: battery life extension through solar panel recharging, computer memory program retention in the event of battery failure and built-in lightning protection. For complex operating conditions, controllers can be purchased that have multiple valve capability to fully automate the production process.
Modern plungers are designed with various sidewall geometries and can be generally described as follows:                A. Shifting ring plungers for continuous contact against the tubing to produce an effective seal with wiping action to ensure that all scale, salt or paraffin is removed from the tubing wall. Some designs have by-pass valves to permit fluid to flow through during the return trip to the bumper spring with the by-pass shutting when the plunger reaches the bottom. The by-pass feature optimizes plunger travel time in high liquid wells.        B. Pad plungers with spring-loaded interlocking pads in one or more sections. The pads expand and contract to compensate for any irregularities in the tubing thus creating a tight friction seal. Pad plungers can also have a by-pass valve as described above.        C. Brush plungers incorporate a spiral-wound, flexible nylon brush section to create a seal and allow the plunger to travel despite the presence of sand, coal fines, tubing irregularities, etc. By-pass valves may also be incorporated.        D. Solid plungers with solid sidewall rings for durability. Solid sidewall rings can be made of various materials such as steel, poly materials, Teflon, stainless steel, etc. Once again, by-pass valves can be incorporated.        E. Snake plungers, which are flexible for coiled tubing and directional holes, and can be used as well in straight standard tubing.        
Recent practices toward slim-hole wells that utilize coiled tubing lend also themselves to plunger systems. Because of the small tubing diameters, a relatively small amount of liquid may cause a well to load-up or a relatively small amount of paraffin may plug the tubing.
Plungers use the volume of gas stored in the casing and the formation during the shut-in time to push the liquid load and plunger to surface when the motor valve opens the well to the sales line or to the atmosphere. To operate a plunger installation, only the pressure and gas volume in the tubing/casing annulus is usually considered as the source of energy for bringing the liquid load and plunger to surface.
The major forces acting on the cross-sectional area of the bottom of the plunger are:                The pressure of the gas in the casing pushes up on the liquid load and the plunger;        The sales line operating pressure and atmospheric pressure push down on the plunger;        The weight of the liquid and the plunger pushes down on the plunger;        Once the plunger begins moving to the surface, friction between the tubing and the liquid load acts to oppose the plunger;        In addition, friction between the gas and tubing acts to slow the expansion of the gas.        
The major disadvantage of conventional plunger lifts is that the well must be shut-in in order for the plunger to fall to the bottom of the well. Two part plunger systems (ball-type or other non-positive mechanical plungers) can lose plunger piece to piece contact during lift due a drop in critical velocity, collar banging, hitting slugs of fluid, paraffin or scale particles, which decreases well efficiency. If the ball falls back to the bottom, fluid is then allowed to fall back to the bottom, which keeps the well in a loaded state. The only thing that holds the ball on the plunger is the upward flow of gas and fluid. See U.S. Pat. Nos. 6,209,637 and 6,467,544 to Wells. When the Wells two-part piston rises, changing well conditions can cause the ball to disconnect from the sleeve, resulting in lost well production.
The present invention in its various embodiments latches a lower plug to an upper sleeve, thereby preventing an accidental separation. Plunger drop travel time slows or limits well production. Also fishing balls out of a well is a problem and sometimes requires pulling the complete tubing string. Well production increases are always critical. What is needed is a plunger lift apparatus that can insure a positive contact during lift, drop back to the well bottom quickly and easily and assist in increasing well production by increasing lift cycle times. What is also needed is a two-part plunger system that is retrievable from the well. The apparatus of the present invention provides a solution to these aforementioned deficiencies.